Petroleum Engineering
Arezou Jafari; Peyman Sadirli; Reza Gharibshahi; Esmaeel Kazemi Tooseh; Masoud Samivand; Ali Teymouri
Abstract
Natural gas storage process in aquifer, due to fluid flow behavior of gas and water in the porous medium and because of their contact with each other under reservoir conditions, faces several challenges. Therefore, there should be a clear understanding of the injected gas behavior before and after the ...
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Natural gas storage process in aquifer, due to fluid flow behavior of gas and water in the porous medium and because of their contact with each other under reservoir conditions, faces several challenges. Therefore, there should be a clear understanding of the injected gas behavior before and after the injection into the reservoir. This research simulates the natural gas storage in aquifer by using Eclipse 300 software. For this purpose, a core sample was considered as the porous medium for gas injection, and a composition of natural gas was injected into the core in different conditions. Moreover, by using Plackett-Burman method, all of the factors affected in this process were screened, and finally four main significant parameters, including the flow rate of injected gas, permeability, pressure, and irreducible water saturation were selected for designing a design of experiments (DOE) plan. Response surface method (RSM) is one of the best methods of experimental design used for optimizing the process and finding the best combination of parameters to have a high stored gas volume and a high recovered gas volume. The simulation includes 28 runs with four considered parameters, and the output is the recovered gas, which in turn is vital for the process accomplishment. Sensitivity analysis and grid independency test were checked. To this end, three grids with different number of cells in x-direction were generated, and by analyzing the results of gas saturation in the porous medium for each model, a grid with 11250 cells (50 elements in x-direction and 15 elements in y- and z-directions) was then chosen as the main grid. Uncertainty analysis and the validation of numerical simulations were carried out, and good agreement was observed between the numerical results and experimental data. In addition, the numerical results showed that the flow rate of the injected gas had a significant impact on the process in comparison with other parameters. Furthermore, increasing permeability and decreasing pressure and irreducible water saturation raise the amount of trapped gas in aquifers. Therefore, for having the maximum stored gas volume and a high recovered gas volume, the best combination of parameters is a high gas injection flow rate (0.9 cc/min), high permeability (1.54 md), a low pressure (2254 psi), and irreducible water saturation. (0.46). Finally, in a natural gas storage operation in an aquifer, both rock properties and operational parameters play important roles, and they should be optimized in order to have the highest amount of stored gas.
Petroleum Engineering
Mohammad Hossein Shabani; Arezou Jafari; Seyed Mohammad Mousavi
Abstract
Microbial enhanced oil recovery (MEOR) is an economical method used to improve the oil recovery from reservoirs. In the MEOR techniques, by applying different microorganisms, a variety of products such as bioacid, biogas, biosurfactant, and biopolymer are generated, among which biosurfactant, one of ...
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Microbial enhanced oil recovery (MEOR) is an economical method used to improve the oil recovery from reservoirs. In the MEOR techniques, by applying different microorganisms, a variety of products such as bioacid, biogas, biosurfactant, and biopolymer are generated, among which biosurfactant, one of the important metabolites, is produced by bacteria. It is worthy to note that bacteria are suitable candidates to enhance oil recovery due to their small size, rapid growth, capability of tolerating reservoir conditions, and production of different metabolites. Therefore, in this research, two bacteria, namely Enterobacter cloacae subsp with PTCC: 1798 isolated from oil-contaminated soil in south of Iran and Acinetobacter Calcoaceticus with PTCC: 1318, are used to produce biosurfactants. In order to evaluate the performance of generated biosurfactants, ex-situ flooding tests were performed in a glass micromodel to visualize the oil displacement and fluid front flow. In addition, water flooding is performed as a common EOR method for the better investigation of the produced biosurfactants. The results represented that injecting Enterobacter with a salinity concentration of 6% and Acinetobacter with a salinity concentration of 3% respectively increases the oil recovery factor by 27 and 35% compared to water flooding. In other words, the highest reduction in interfacial tension is achieved by the biosurfactant produced from Enterobacter and Acinetobacter at 6% and 3% salinity respectively, and the sequent changes in the interfacial tension are from 45 to 7 and 45 to 4 mN/m.
